Sour NGL Stream Recovery

ABSTRACT

A method for recovering a sour natural gas liquids stream is provided. In one embodiment, a carbon dioxide recycle stream that comprises carbon dioxide, natural gas liquids, and acid gas is received. The carbon dioxide recycle stream is separated into a purified carbon dioxide recycle stream and a natural gas liquids stream. The purified carbon dioxide recycle stream comprises the carbon dioxide, and the natural gas liquids stream comprises the natural gas liquids and the acid gas. In another embodiment, a system comprises piping and a separator. The piping is configured to receive a recycle stream that comprises an injection gas, natural gas liquids, and acid gas. The separator is configured to separate the recycle stream into a purified recycle stream and a natural gas liquids stream. The purified recycle stream comprises the injection gas, and the natural gas liquids stream comprises the natural gas liquids and the acid gas.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 13/096,788 filed Apr. 28, 2011, which claimspriority to U.S. patent application Ser. No. 12/122,336 filed May 16,2008, which claims priority to U.S. Provisional Patent Application No.60/938,726 filed May 18, 2007, all of which are incorporated herein byreference as if reproduced in their entirety. The present applicationalso claims priority to U.S. Provisional Patent Application No.61/730,696 filed Nov. 28, 2012 and U.S. Provisional Application No.61/823,047 filed May 14, 2013, both of which are incorporated herein byreference as if reproduced in their entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Carbon dioxide (CO₂) is a naturally occurring substance in mosthydrocarbon subterranean formations. Carbon dioxide also may be used forrecovering or extracting oil and hydrocarbons from subterraneanformations. One carbon dioxide based recovery process involves injectingcarbon dioxide into an injection well, and recovering heavy hydrocarbonsand perhaps some of the carbon dioxide from at least one recovery well.Carbon dioxide reinjection process also may produce natural gas liquids(NGLs).

SUMMARY

In one aspect, the disclosure includes a method for recovering a sournatural gas liquids stream. A carbon dioxide recycle stream thatcomprises carbon dioxide, natural gas liquids, and acid gas is received.The carbon dioxide recycle stream is separated into a purified carbondioxide recycle stream and a natural gas liquids stream. The purifiedcarbon dioxide recycle stream comprises the carbon dioxide, and thenatural gas liquids stream comprises the natural gas liquids and theacid gas.

In another aspect, the disclosure includes a system comprising pipingand a separator. The piping is configured to receive a recycle streamthat comprises an injection gas, natural gas liquids, and acid gas. Theseparator is coupled to the piping and is configured to separate therecycle stream into a purified recycle stream and a natural gas liquidsstream. The purified recycle stream comprises the injection gas, and thenatural gas liquids stream comprises the natural gas liquids and theacid gas.

In yet another aspect, the disclosure includes a set of processequipment comprising an input line, a separator, a first output line,and a second output line. The input line is configured to receive arecycle stream, wherein the recycle stream comprises an injection gas,natural gas liquids, and acid gas. The separator is configured toreceive the recycle stream from the input line and separate the recyclestream into a purified recycle stream and a natural gas liquids stream.The first output line is configured to output the purified recyclestream from the separator, wherein the purified recycle stream comprisesthe injection gas, and the second output line is configured to outputthe natural gas liquids stream from the separator, wherein the naturalgas liquids stream comprises the natural gas liquids and the acid gas.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process flow diagram for an embodiment of a carbon dioxidereinjection process.

FIG. 2 is a schematic diagram of an embodiment of an NGL recoveryprocess.

FIG. 3 is a chart depicting an embodiment of the relationship betweenthe NGL recovery rate and the energy requirement.

FIG. 4 is a schematic diagram of an embodiment of an NGL upgradeprocess.

FIG. 5 is a process flow diagram for another embodiment of a reinjectionprocess.

FIG. 6 is a schematic diagram of another embodiment of an NGL recoveryprocess.

FIG. 7 is a flowchart of an embodiment of an NGL recovery optimizationmethod.

DETAILED DESCRIPTION

It should be understood at the outset that although an illustrativeimplementation of one or more embodiments are provided below, thedisclosed systems and/or methods may be implemented using any number oftechniques, whether currently known or in existence. The disclosureshould in no way be limited to the illustrative implementations,drawings, and techniques illustrated below, including the exemplarydesigns and implementations illustrated and described herein, but may bemodified within the scope of the appended claims along with their fullscope of equivalents.

Disclosed herein is an NGL recovery process that may be implemented aspart of a carbon dioxide reinjection process to recover NGLs from acarbon dioxide recycle stream. When implementing a carbon dioxidereinjection process, the carbon dioxide is typically injected downholeinto an injection well and a stream comprising hydrocarbons and carbondioxide is generally recovered from a recovery well. The carbon dioxidemay be separated from the heavy hydrocarbons and then recycled downhole,e.g., in the reinjection well. In some cases, the carbon dioxide recyclestream may comprise some NGLs, which may be recovered prior to injectingthe carbon dioxide recycle stream downhole. The NGL recovery process maybe optimized by weighing the NGL recovery rate against the amount ofenergy expended on NGL recovery.

FIG. 1 illustrates an embodiment of a carbon dioxide reinjection process100. The carbon dioxide reinjection process 100 may receive hydrocarbonsand carbon dioxide from a subterranean hydrocarbon formation 114,separate heavy hydrocarbons and some of the NGLs from the carbondioxide, and inject the carbon dioxide downhole. As shown in FIG. 1,additional process steps may be included in the carbon dioxidereinjection process, such as compressing the carbon dioxide, dehydratingthe carbon dioxide, and/or adding additional carbon dioxide to thecarbon dioxide recycle stream. The specific steps in the carbon dioxidereinjection process 100 are explained in further detail below.

The carbon dioxide reinjection process 100 may receive a hydrocarbonfeed stream 152 from a subterranean hydrocarbon formation 114. Thehydrocarbon feed stream 152 may be obtained from at least one recoverywell as indicated by the upward arrow in FIG. 1, but also may beobtained from other types of wells. In addition, the hydrocarbon feedstream 152 may be obtained from the subterranean hydrocarbon formation114 using any suitable method. For example, if a suitable pressuredifferential exists between the subterranean hydrocarbon formation 114and the surface, the hydrocarbon feed stream 152 may flow to the surfacevia the pressure differential. Alternatively, surface and/or downholepumps may be used to draw the hydrocarbon feed stream 152 from thesubterranean hydrocarbon formation 114 to the surface.

Although the composition of the hydrocarbon feed stream 152 will varyfrom one location to another, the hydrocarbon feed stream 152 maycomprise carbon dioxide, methane, ethane, NGLs, heavy hydrocarbons,hydrogen sulfide (H₂S), helium, nitrogen, water, or combinationsthereof. The term “hydrocarbon” may refer to any compound comprising,consisting essentially of, or consisting of carbon and hydrogen atoms.The term “natural gas” may refer to any hydrocarbon that may exist in agas phase under atmospheric or downhole conditions, and includes methaneand ethane, but also may include diminishing amounts of C₃-C₈hydrocarbons. The term “natural gas liquids” or NGLs may refer tonatural gases that may be liquefied without refrigeration, and mayinclude C₃-C₈ hydrocarbons. Both natural gas and NGL are terms known inthe art and are used herein as such. In contrast, the term “heavyhydrocarbons” may refer to any hydrocarbon that may exist in a liquidphase under atmospheric or downhole conditions, and generally includesliquid crude oil, which may comprise C₉₊ hydrocarbons, branchedhydrocarbons, aromatic hydrocarbons, and combinations thereof.

The hydrocarbon feed stream 152 may enter a separator 102. The separator102 may be any process equipment suitable for separating at least oneinlet stream into a plurality of effluent streams having differentcompositions, states, temperatures, and/or pressures. For example, theseparator 102 may be a column having trays, packing, or some other typeof complex internal structure. Examples of such columns includescrubbers, strippers, absorbers, adsorbers, packed columns, anddistillation columns having valve, sieve, or other types of trays. Suchcolumns may employ weirs, downspouts, internal baffles, temperaturecontrol elements, and/or pressure control elements. Such columns alsomay employ some combination of reflux condensers and/or reboilers,including intermediate stage condensers and reboilers. Alternatively,the separator 102 may be a phase separator, which is a vessel thatseparates an inlet stream into a substantially vapor stream and asubstantially liquid stream, such as a knock-out drum, flash drum,reboiler, condenser, or other heat exchanger. Such vessels also may havesome internal baffles, temperature control elements, and/or pressurecontrol elements, but generally lack any trays or other type of complexinternal structure commonly found in columns. The separator 102 also maybe any other type of separator, such as a membrane separator. In aspecific embodiment, the separator 102 is a knockout drum. Finally, theseparator 102 may be any combination of the aforementioned separatorsarranged in series, in parallel, or combinations thereof.

The separator 102 may produce a heavy hydrocarbon stream 154 and acarbon dioxide recycle stream 156. The heavy hydrocarbon stream 154 maycomprise most of the heavy hydrocarbons from the hydrocarbon feed stream152. In embodiments, the heavy hydrocarbon stream 154 may comprise atleast about 90 percent, at least about 95 percent, at least about 99percent, or substantially all of the heavy hydrocarbons from thehydrocarbon feed stream 152. The heavy hydrocarbon stream 154 may besent to a pipeline for transportation or a storage tank 104, where it isstored until being transported to another location or being furtherprocessed. In contrast, the carbon dioxide recycle stream 156 maycomprise most of the carbon dioxide from the hydrocarbon feed stream152. In embodiments, the carbon dioxide recycle stream 156 may compriseat least about 90 percent, at least about 95 percent, at least about 99percent, or substantially all of the carbon dioxide from the hydrocarbonfeed stream 152. Similarly, the carbon dioxide recycle stream 156 maycomprise at least about 80 percent, at least about 90 percent, at leastabout 95 percent, or substantially all of the natural gas from thehydrocarbon feed stream 152. All of the percentages referred to hereinare molar percentages until otherwise specified.

The carbon dioxide recycle stream 156 may enter a compressor 106. Thecompressor 106 may be any process equipment suitable for increasing thepressure, temperature, and/or density of an inlet stream. The compressor106 may be configured to compress a substantially vapor phase inletstream, a substantially liquid phase inlet stream, or combinationsthereof. As such, the term “compressor” may include both compressors andpumps, which may be driven by electrical, mechanical, hydraulic, orpneumatic means. Specific examples of suitable compressors 106 includecentrifugal, axial, positive displacement, turbine, rotary, andreciprocating compressors and pumps. In a specific embodiment, thecompressor 106 is a turbine compressor. Finally, the compressor 106 maybe any combination of the aforementioned compressors arranged in series,in parallel, or combinations thereof.

The compressor 106 may produce a compressed carbon dioxide recyclestream 158. The compressed carbon dioxide recycle stream 158 may containthe same composition as the carbon dioxide recycle stream 156, but at ahigher energy level. The additional energy in the compressed carbondioxide recycle stream 158 may be obtained from energy added to thecompressor 106, e.g., the electrical, mechanical, hydraulic, orpneumatic energy. In embodiments, difference in energy levels betweenthe compressed carbon dioxide recycle stream 158 and the carbon dioxiderecycle stream 156 is at least about 50 percent, at least about 65percent, or at least about 80 percent of the energy added to thecompressor 106.

The compressed carbon dioxide recycle stream 158 may enter a dehydrator108. The dehydrator 108 may remove some or substantially all of thewater from the compressed carbon dioxide recycle stream 158. Thedehydrator 108 may be any suitable dehydrator, such as a condenser, anabsorber, or an adsorber. Specific examples of suitable dehydrators 108include refrigerators, molecular sieves, liquid desiccants such asglycol, solid desiccants such as silica gel or calcium chloride, andcombinations thereof. The dehydrator 108 also may be any combination ofthe aforementioned dehydrators arranged in series, in parallel, orcombinations thereof. In a specific embodiment, the dehydrator 108 is aglycol unit. Any water accumulated within or exiting from the dehydrator108 may be stored, used for other processes, or discarded.

The dehydrator 108 may produce a dehydrated carbon dioxide recyclestream 160. The dehydrated carbon dioxide recycle stream 160 may containlittle water, e.g., liquid water or water vapor. In embodiments, thedehydrated carbon dioxide recycle stream 160 may comprise no more thanabout 5 percent, no more than about 3 percent, no more than about 1percent, or be substantially free of water.

The dehydrated carbon dioxide recycle stream 160 may enter an NGLrecovery process 110. The NGL recovery process 110 may separate thedehydrated carbon dioxide recycle stream 160 into an NGL rich stream 162and a purified carbon dioxide recycle stream 164. The NGL rich stream162 may only comprise a portion of the total NGLs from the dehydratedcarbon dioxide recycle stream 160. For example, the NGL rich stream 162may comprise less than about 70 percent, from about 10 percent to about50 percent, or from about 20 percent to about 35 percent of the NGLsfrom the dehydrated carbon dioxide recycle stream 160. By taking a lessaggressive cut of the NGLs and/or disregarding the recovery of methane,ethane, and optionally propane from the dehydrated carbon dioxiderecycle stream 160, the NGL recovery process 110 may produce arelatively high quality NGL rich stream 162 with relatively littleprocess equipment or energy. A specific example of a suitable NGLrecovery process 110 is shown in FIG. 2 and described in further detailbelow.

As mentioned above, the NGL recovery process 110 may produce arelatively high-quality NGL rich stream 162. Specifically, while the NGLrecovery process 110 recovers only a portion, e.g., about 20 to about 35percent, of the NGLs in the dehydrated carbon dioxide recycle stream160, the resulting NGL rich stream 162 is relatively lean with respectto methane and the acid gases. For example, the NGL rich stream 162 maycomprise most of the butane and heavier components from the dehydratedcarbon dioxide recycle stream 160. For example, the NGL rich stream 162may comprise at least about 90 percent, at least about 95 percent, atleast about 99 percent, or substantially all of the C₄₊ from thedehydrated carbon dioxide recycle stream 160. In an embodiment, the NGLrich stream 162 may comprise at least about 20 percent, at least about40 percent, at least about 60 percent, or at least about 70 percent ofthe C₃₊ from the dehydrated carbon dioxide recycle stream 160. Inembodiments, the NGL rich stream 162 may comprise no more than about 10percent, no more than about 5 percent, no more than about 1 percent, orbe substantially free of ethane. Similarly, the NGL rich stream 162 maycomprise no more than about 5 percent, no more than about 3 percent, nomore than about 1 percent, or be substantially free of methane.Moreover, the NGL rich stream 162 may comprise no more than about 5percent, no more than about 3 percent, no more than about 1 percent, orbe substantially free of acid gases, such as carbon dioxide or hydrogensulfide. It will be realized that the composition of the NGL rich stream162 may be dependent on the dehydrated carbon dioxide recycle stream 160composition. The examples provided below show the composition of the NGLrich stream 162 for three different dehydrated carbon dioxide recyclestream 160 compositions. The NGL rich stream 162 may be sent to apipeline for transportation or a storage tank, where it is stored untilbeing transported to another location or being further processed.

In an embodiment, the NGL rich stream 162 optionally may be processed inan NGL upgrade process 170. The NGL upgrade process 170 may produce arelatively heavy NGL stream 172 that may be combined with the heavyhydrocarbon stream 154. When combined, the heavy NGL stream 172 and theheavy hydrocarbon stream 154 may meet or exceed the pipeline and/ortransportation thresholds or standards for a heavy hydrocarbon stream,as described in more detail with respect to FIG. 4. A relatively lightNGL stream 174 may be sent to a pipeline for transportation or a storagetank, where it may be stored until transported to another location orfurther processed, as described in more detail with respect to FIG. 4. Aspecific example of a suitable NGL upgrade process 170 is shown in FIG.5 and described in further detail below.

As mentioned above, the NGL recovery process 110 may produce a purifiedcarbon dioxide recycle stream 164. The purified carbon dioxide recyclestream 164 may comprise most of the carbon dioxide from the dehydratedcarbon dioxide recycle stream 160, as well as some other components suchas methane, ethane, propane, butane, nitrogen, and hydrogen sulfide. Inembodiments, the purified carbon dioxide recycle stream 164 may compriseat least about 90 percent, at least about 95 percent, at least about 99percent, or substantially all of the carbon dioxide from the dehydratedcarbon dioxide recycle stream 160. In addition, the purified carbondioxide recycle stream 164 may comprise at least about 90 percent, atleast about 95 percent, at least about 99 percent, or substantially allof the methane from the dehydrated carbon dioxide recycle stream 160. Assuch, the purified carbon dioxide recycle stream 164 may comprise atleast about 65 percent, at least about 80 percent, at least about 90percent, or at least about 95 percent carbon dioxide. In embodiments,the purified carbon dioxide recycle stream 164 may comprise no more thanabout 10 percent, no more than about 5 percent, no more than about 1percent, or be substantially free of C₃₊. Similarly, the purified carbondioxide recycle stream 164 may comprise no more than about 20 percent,no more than about 10 percent, no more than about 5 percent, or besubstantially free of C₂₊.

The purified carbon dioxide recycle stream 164 may enter a compressor112. The compressor 112 may comprise one or more compressors, such asthe compressor 106 described above. In a specific embodiment, thecompressor 112 is a turbine compressor. The compressor 112 may compressthe purified carbon dioxide recycle stream 164, thereby producing acarbon dioxide injection stream 168. The carbon dioxide injection stream168 may contain the same composition as the purified carbon dioxiderecycle stream 164, but at a higher energy level. The additional energyin the carbon dioxide injection stream 168 may be obtained from energyadded to the compressor 112, e.g., the electrical, mechanical,hydraulic, or pneumatic energy. In some embodiments, the difference inenergy levels between the carbon dioxide injection stream 168 and thepurified carbon dioxide recycle stream 164 is at least about 50 percent,at least about 65 percent, or at least about 80 percent of the energyadded to the compressor 112.

In some embodiments, a makeup stream 166 may be combined with either thepurified carbon dioxide recycle stream 164 or the carbon dioxideinjection stream 168. Specifically, as the carbon dioxide reinjectionprocess 100 is operated, carbon dioxide and other compounds will belost, e.g., by replacing the hydrocarbons in the subterraneanhydrocarbon formation 114, by leakage into inaccessible parts of thesubterranean hydrocarbon formation 114, and/or to other causes.Alternatively, it may be desirable to increase the amount of carbondioxide and other compounds injected downhole. As such, the makeupstream 166 may be combined with either the purified carbon dioxiderecycle stream 164 and/or the carbon dioxide injection stream 168, forexample in the compressor 112. Alternatively or additionally, the makeupstream 166 may be combined with the carbon dioxide recycle stream 156,the compressed carbon dioxide recycle stream 158, the dehydrated carbondioxide recycle stream 160, or combinations thereof. The makeup stream166 may comprise carbon dioxide, nitrogen, methane, ethane, air, water,or any other suitable compound. In an embodiment, the makeup stream 166comprises at least 75 percent, at least 85 percent, or at least 95percent carbon dioxide, nitrogen, methane, air, water, or combinationsthereof. Finally, the carbon dioxide injection stream 168 may be sent toa carbon dioxide pipeline rather than being immediately injecteddownhole. In such a case, the carbon dioxide injection stream 168 maymeet the carbon dioxide pipeline specifications. One example of a carbondioxide pipeline specification is: at least about 95 percent carbondioxide, substantially free of free water, no more than about 30 poundsof vapor-phase water per million cubic feet (mmcf) of product, no morethan about 20 parts per million (ppm) by weight of hydrogen sulfide, nomore than about 35 ppm by weight of total sulfur, a temperature of nomore than about 120° F., no more than about four percent nitrogen, nomore than about five percent hydrocarbons (wherein the hydrocarbons donot have a dew point exceeding about −20° F.), no more than about 10 ppmby weight of oxygen, and more than about 0.3 gallons of glycol per mmcfof product (wherein the glycol is not in the liquid state at thepressure and temperature conditions of the pipeline).

FIG. 2 illustrates an embodiment of an NGL recovery process 200. The NGLrecovery process 200 may recover some of the NGLs from a carbon dioxiderecycle stream described above. For example, the NGL recovery process200 may be implemented as part of the carbon dioxide reinjection process100, e.g., by separating the dehydrated carbon dioxide recycle stream160 into an NGL rich stream 162 and a purified carbon dioxide recyclestream 164. Alternatively, the NGL recovery process 200 may beimplemented as a stand-alone process for recovering NGLs from ahydrocarbon containing stream.

The NGL recovery process 200 may begin by cooling the dehydrated carbondioxide recycle stream 160 in a heat exchanger 202. The heat exchanger202 may be any equipment suitable for heating or cooling one streamusing another stream. Generally, the heat exchanger 202 is a relativelysimple device that allows heat to be exchanged between two fluidswithout the fluids directly contacting each other. Examples of suitableheat exchangers 202 include shell and tube heat exchangers, double pipeheat exchangers, plate fin heat exchangers, bayonet heat exchangers,reboilers, condensers, evaporators, and air coolers. In the case of aircoolers, one of the fluids comprises atmospheric air, which may beforced over tubes or coils using one or more fans. In a specificembodiment, the heat exchanger 202 is a shell and tube heat exchanger.

As shown in FIG. 2, the dehydrated carbon dioxide recycle stream 160 maybe cooled using the cooled, purified carbon dioxide recycle stream 258.Specifically, the dehydrated carbon dioxide recycle stream 160 is cooledto produce the cooled carbon dioxide recycle stream 252, and the cooled,purified carbon dioxide recycle stream 258 is heated to produce thepurified carbon dioxide recycle stream 164. The efficiency of the heatexchange process depends on several factors, including the heatexchanger design, the temperature, composition, and flowrate of the hotand cold streams, and/or the amount of thermal energy lost in the heatexchange process. In embodiments, the difference in energy levelsbetween the dehydrated carbon dioxide recycle stream 160 and the cooledcarbon dioxide recycle stream 252 is at least about 60 percent, at leastabout 70 percent, at least about 80, or at least about 90 percent of thedifference in energy levels between the cooled, purified carbon dioxiderecycle stream 258 and the purified carbon dioxide recycle stream 164.

The cooled carbon dioxide recycle stream 252 then enters an NGLstabilizer 204. The NGL stabilizer 204 may comprise a separator 206, acondenser 208, and a reboiler 210. The separator 206 may be similar toany of the separators described herein, such as separator 102. In aspecific embodiment, the separator 206 is a distillation column. Thecondenser 208 may receive an overhead 254 from the separator 206 andproduce the cooled, purified carbon dioxide recycle stream 258 and areflux stream 256, which is returned to the separator 206. The condenser208 may be similar to any of the heat exchangers described herein, suchas heat exchanger 202. In a specific embodiment, the condenser 208 is ashell and tube, kettle type condenser coupled to a refrigerationprocess, and contains a reflux accumulator. As such, the condenser 208may remove some energy 282 from the reflux stream 256 and cooled,purified carbon dioxide recycle stream 258, typically by refrigeration.The cooled, purified carbon dioxide recycle stream 258 is substantiallysimilar in composition to the purified carbon dioxide recycle stream 164described above. Similarly, the reboiler 210 may receive a bottomsstream 260 from the separator 206 and produce a sour NGL rich stream 264and a boil-up stream 262, which is returned to the separator 206. Thereboiler 210 may be like any of the heat exchangers described herein,such as heat exchanger 202. In a specific embodiment, the reboiler 210is a shell and tube heat exchanger coupled to a hot oil heater. As such,the reboiler 210 adds some energy 284 to the boil-up stream 262 and thesour NGL rich stream 264, typically by heating. The sour NGL rich stream264 may be substantially similar in composition to the NGL rich stream162, with the exception that the sour NGL rich stream 264 has someadditional acid gases, e.g., acid gases 270 described below.

The sour NGL rich stream 264 then may be cooled in another heatexchanger 212. The heat exchanger 212 may be like any of the heatexchangers described herein, such as heat exchanger 202. For example,the heat exchanger 212 may be an air cooler as described above. Acooled, sour NGL rich stream 266 may exit the heat exchanger 212 andenter a throttling valve 214. The throttling valve 214 may be an actualvalve such as a gate valve, globe valve, angle valve, ball valve,butterfly valve, needle valve, or any other suitable valve, or may be arestriction in the piping such as an orifice or a pipe coil, bend, orsize reduction. The throttling valve 214 may reduce the pressure,temperature, or both of the cooled, sour NGL rich stream 266 and producea low-pressure sour NGL rich stream 268. The cooled, sour NGL richstream 266 and the low-pressure sour NGL rich stream 268 havesubstantially the same composition as the sour NGL rich stream 264,albeit with lower energy levels.

The low-pressure sour NGL rich stream 268 then may be sweetened in aseparator 216. The separator 216 may be similar to any of the separatorsdescribed herein, such as separators 102 or 206. In an embodiment, theseparator 216 may be one or more packed columns that use a sweeteningprocess to remove acid gases from the low-pressure sour NGL rich stream268. Suitable sweetening processes include amine solutions, physicalsolvents such as SELEXOL or RECTISOL, mixed amine solution and physicalsolvents, potassium carbonate solutions, direct oxidation, absorption,adsorption using, e.g., molecular sieves, or membrane filtration. Theseparator 216 may produce the NGL rich stream 162 described above. Inaddition, any acid gases 270 accumulated within or exiting from theseparator 216 may be stored, used for other processes, or suitablydisposed of. Finally, while FIGS. 1 and 2 are described in the contextof carbon dioxide reinjection, it will be appreciated that the conceptsdescribed herein can be applied to other reinjection processes, forexample those using nitrogen, air, or water.

FIG. 3 illustrates an embodiment of a chart 300 depicting therelationship between the NGL recovery rate and the energy expended torecover NGLs in the NGL recovery process. The NGL recovery rate may be apercentage recovery, and may represent the amount of C₃₊ in the carbondioxide recycle stream that is recovered in the NGL rich stream. Theenergy requirement may be measured in joules (J) or in horsepower (hp),and may represent the energy required to generate the condenser energyand reboiler energy described above. If additional compressors areneeded at any point in the carbon dioxide reinjection process than wouldbe required in an otherwise similar carbon dioxide reinjection processthat lacks the NGL recovery process, then the energy required to operatesuch compressors may be included in the energy requirement shown in FIG.3.

As shown by curve 302, the energy requirements may increase aboutexponentially as the NGLs are recovered at higher rates. In other words,substantially higher energy may be required to recover the NGLs atincrementally higher rates. For example, recovering a first amount 304of from about 20 percent to about 35 percent of C₃₊ may requiresubstantially less energy than recovering a second amount 306 of fromabout 40 percent to about 65 percent of C₃₊. Moreover, recovering thesecond amount 306 of from about 40 percent to about 65 percent of C₃₊may require substantially less energy than recovering a third amount 308of from about 70 percent to about 90 percent of C₃₊. Such significantreduction in energy requirements may be advantageous in terms of processfeasibility and cost, where relatively small decreases in NGL recoveryrates may require significantly less energy and process equipment,yielding significantly better process economics. Although the exactrelationship of the curve 302 may depend on numerous factors especiallythe price of C₃₊, in an embodiment the economics of the NGL recoveryprocess when the NGL recovery rate is in the second amount 306 may bebetter than the economics of the NGL recovery process when the NGLrecovery rate is in the third amount 308. Similarly, the economics ofthe NGL recovery process when the NGL recovery rate is in the firstamount 304 may be significantly better than the economics of the NGLrecovery process when the NGL recovery rate is in the second amount 306.Such a relationship is counterintuitive considering that in many otherprocesses, the process economics generally improve with increasedrecovery rates.

FIG. 4 illustrates an embodiment of an NGL upgrade process 500. The NGLupgrade process 500 may separate a portion of the heavier components ofthe NGL rich stream 162 for blending with the heavy hydrocarbon stream154. For example, the NGL upgrade process 500 may be used to produce arelatively heavy NGL stream 172 for combining with the heavy hydrocarbonstream 154 and a relatively light NGL stream 174 that may be sold and/orused as an NGL product. In general, the heavy hydrocarbon stream 154 maysell for a higher price than the NGL rich stream 162. By mixing at leasta portion of the NGL rich stream 162 with the heavy hydrocarbon stream154, the NGL upgrade process 500 may be used to improve the economicsand/or revenue from the NGL recovery process. As a result, the NGLupgrade process 500 may be considered in the NGL recovery optimizationmethod 400 described in more detail below.

The NGL upgrade process 500 may begin by passing the NGL rich stream 162into an NGL upgrade unit 502. The NGL rich stream 162 may be in theliquid phase after passing through separator 216. The NGL upgrade unit502 may comprise a separator 506, and a reboiler 510. While notillustrated in FIG. 4, some embodiments of the NGL upgrade unit 502 alsomay comprise a condenser. The separator 506 may be similar to any of theseparators described herein, such as separator 102. In a specificembodiment, the separator 506 is a stripping column with a partialreboiler 510, and the separator 506 may not comprise a condenser. Thedowncoming liquid phase may be provided by the liquid NGL rich stream162, which may be introduced at or near the top of the separator 506. Inan embodiment, a condenser may be used to at least partially condenseoverhead stream 524 to produce at least a portion of the downcomingliquid in separator 506. For example, the condenser may be similar toany of the heat exchangers described herein, such as heat exchanger 202.The reboiler 510 may receive a bottoms stream 508 from the separator 506and produce a heavy NGL stream 514 and a boil-up stream 512, which isreturned to the separator 506 to provide the rising vapor phase withinthe separator 506. The reboiler 510 may be like any of the heatexchangers described herein, such as heat exchanger 202. In a specificembodiment, the reboiler 510 is a shell and tube heat exchanger coupledto a hot oil heater. As such, the reboiler 510 adds some energy 516 tothe boil-up stream 512 and the heavy NGL stream 514, typically byheating. The heavy NGL stream 514 may be substantially similar incomposition to the heavy NGL stream 172.

The heavy NGL stream 514 then may be cooled in a heat exchanger 518. Theheat exchanger 518 may be any equipment suitable for heating or coolingone stream using another stream. Generally, the heat exchanger 518 is arelatively simple device that allows heat to be exchanged between twofluids without the fluids directly contacting each other (i.e., indirectheat exchange). In an embodiment, heat integration that comprises usingone or more streams in the overall process to cool the heavy NGL stream514, and thereby heating the one or more streams, may be used with heatexchanger 518. Examples of suitable heat exchangers 518 include shelland tube heat exchangers, double pipe heat exchangers, plate fin heatexchangers, bayonet heat exchangers, reboilers, condensers, evaporators,and air coolers. In the case of air coolers, one of the fluids compriseatmospheric air, which may be forced over tubes or coils using one ormore fans. In a specific embodiment, the heat exchanger 518 is a shelland tube heat exchanger with the heavy NGL stream 514 passing on oneside of the exchanger and a cooling fluid stream 522 passing on theother. The cooled, heavy NGL stream 172 may have substantially the samecomposition as the heavy NGL stream 514, albeit with lower energylevels.

The overhead stream 524 from separator 506 may comprise at least aportion of the lighter NGL components and may be cooled in another heatexchanger 526. The heat exchanger 526 may be like any of the heatexchangers described herein, such as heat exchanger 202. For example,the heat exchanger 526 may be an air cooler as described above. Thecooled, light NGL stream 174 may have substantially the same compositionas the overhead stream 524, albeit with lower energy levels.

As shown in FIG. 4, one or more additional NGL input streams 530, 532may be introduced into the NGL upgrade process 500 upstream of the NGLupgrade unit 502. The additional NGL input streams 530, 532 may compriseNGL streams from any suitable source, such as one or more additionalrecovery plants. The NGL input streams 530, 532 may be transported tothe NGL upgrade unit 502 by any suitable means. For example, the NGLinput streams 530, 532 may be transported to the NGL upgrade unit 502through a pipeline or by truck. The additional NGL input streams 530,532 may contain one or more acid gases and/or other contaminants.Depending on their compositions, the additional NGL input streams 530,532 may be introduced at various input locations in the NGL recoveryprocess. For example, an input location may comprise a point upstream ofthe separator 216 for an NGL input stream 530 comprising acid gascomponents at or above a threshold level (e.g., a pipeline or storagethreshold), thereby allowing for sweetening prior to being introduced tothe downstream processes. As another example, an input location for anNGL input stream 532 that comprises acid gas components below thethreshold level may comprise a point downstream of the separator 216,thereby reducing the energy use of the overall recovery process. The useof one or more additional input streams may allow an NGL upgrade process500 to upgrade the NGL streams from a plurality of NGL recoveryprocesses. For example, multiple NGL recovery processes and/oradditional sources of NGL rich streams may feed the NGL product to anNGL upgrade process, thereby reducing the need to install an NGL upgradeprocess at each source of an NGL stream.

In general, the NGL upgrade process may be used to separate a relativelyheavy NGL stream 172 for blending with the heavy hydrocarbon stream 154.The composition and flowrate of the heavy NGL stream 172 may varydepending on the composition and flowrate of the heavy hydrocarbonstream 154. As discussed above, the heavy hydrocarbon stream 154 may besent to a pipeline for transportation or a storage tank, where it isstored until being transported to another location or being furtherprocessed. Each of the downstream uses for the heavy hydrocarbon stream154 may have one or more thresholds and/or standards that the heavyhydrocarbon stream 154 must meet in order to be transported or furtherprocessed. For example, pipelines may generally have standards settingthresholds for fluids passing through the pipeline, such as thresholdson vapor pressure (e.g., expressed as a Reid vapor pressure standard),carbon dioxide content, acid gas content (e.g., hydrogen sulfidecontent), and water content (e.g., a dew point standard). In anembodiment, the fluid transported in the pipeline may have a Reid vaporpressure of no more than about 20, no more than about 15, or no morethan about 10. Accordingly, the composition and the flowrate of theheavy NGL stream 172 may be controlled so that the heavy hydrocarbonstream 154 may meet the transportation and/or further processingstandards and/or threshold downstream of the mixing point between theheavy hydrocarbon stream 154 and the heavy NGL stream 172.

In an embodiment, the composition and/or flowrate of the heavy NGLstream 172 and the light NGL stream 174 may be controlled, at least inpart, to allow the light NGL stream 174 to satisfy one or moretransportation thresholds. The light NGL stream 174 may be transportedusing a variety of transportation means and/or methods including, butnot limited to, a pipeline and a tanker truck. Each transportationmethod may have one or more thresholds that the light NGL stream 174 mayneed to satisfy prior to being accepted for transportation. For example,a pipeline may have a heating value standard of between about 1,000British thermal units per cubic foot (Btu/ft³) and about 1,200 Btu/ft³,or alternatively between about 1,050 Btu/ft³ and about 1,100 Btu/ft³. Inan embodiment, the light NGL stream 174 also may be subject to a dewpoint standard. As another example, tanker truck transportation may havea vapor pressure requirement that the light NGL stream 174 not exceed avapor pressure of about 250 pounds per square inch gauge (psig) at atemperature of 100° F. Based on the applicable thresholds, thecomposition and the flowrate of the heavy NGL stream 172 and the lightNGL stream 174 may be controlled so that the light NGL stream 174 maymeet the transportation thresholds, allowing the light NGL stream 174 tobe transported for further use.

FIG. 5 illustrates another embodiment of a carbon dioxide reinjectionprocess 600. The process shown in FIG. 5 and the process of FIG. 1 aresimilar, and those portions with similar numbering are described in moredetail with respect to FIG. 1 above. In the interest of brevity, onlythose portions that differ from FIG. 1 will be discussed with respect toFIG. 5.

As can be seen in FIG. 5, the dehydration of the compressed carbondioxide recycle stream 158 may be integrated with the NGLrecovery/dehydration process 610. The compressed carbon dioxide recyclestream 158 may enter an NGL recovery/dehydration process 610. In anembodiment, the NGL recovery/dehydration process 610 may comprise aseparator 102 that produces multiple streams and allow one or morephases of the compressed carbon dioxide recycle stream 158 to bedehydrated without dehydrating the entirety of the compressed carbondioxide recycle stream 158. This may allow for a reduction in the sizeof the dehydration unit and a reduction in the operating expenseassociated with the dehydrator. Further, the separate processing of thephases may allow the downstream processing units to receive each phaseat a different location, which may further improve the process economicsas described in more detail below with respect to FIG. 7.

The compressed carbon dioxide recycle stream 158 may enter the NGLrecovery/dehydration process 610. The NGL recovery/dehydration process610 may dehydrate, process, and separate the compressed carbon dioxiderecycle stream 158 into an NGL rich stream 162 and a purified carbondioxide recycle stream 164. The NGL rich stream 162 may only comprise aportion of the total NGLs from the dehydrated carbon dioxide recyclestream 160. A specific example of a suitable NGL recovery/dehydrationprocess 610 is shown in FIG. 6 and described in further detail below.

As mentioned above, the NGL recovery/dehydration process 610 may producea relatively high-quality NGL rich stream 162. The NGL rich stream 162may have about the same composition as the NGL rich stream 162 inFIG. 1. The NGL rich stream 162 may be sent to a pipeline fortransportation or a storage tank, where it is stored until transportedto another location or further processed. In an embodiment, the NGL richstream optionally may be processed in an NGL upgrade process 170, asdescribed in more detail above. The NGL upgrade process 170 may producea relatively heavy NGL stream 172 that may be combined with the heavyhydrocarbon stream 154. When combined, the heavy NGL stream 172 and theheavy hydrocarbon stream 154 may meet or exceed the pipeline and/ortransportation properties for a heavy hydrocarbon stream. A relativelylight NGL stream 174 may be sent to a pipeline for transportation or astorage tank 104, where it may be stored until being transported toanother location or being further processed. A specific example of asuitable NGL upgrade process 170 is shown in FIG. 4 and described infurther detail above.

As mentioned above, the NGL recovery/dehydration process 610 may producea purified carbon dioxide recycle stream 164. The purified carbondioxide recycle stream 164 may have about the same composition as thepurified carbon dioxide recycle stream 164 in FIG. 1. The purifiedcarbon dioxide recycle stream 164 may enter a compressor 112. Thecompressor 112 may comprise one or more compressors, such as thecompressor 106 described above. In some embodiments, a makeup stream 166may be combined with either the purified carbon dioxide recycle stream164 or the carbon dioxide injection stream 168. The resulting carbondioxide injection stream 168 then may be injected into the subterraneanhydrocarbon formation 114 or sent to a carbon dioxide pipeline.

FIG. 6 illustrates an embodiment of an NGL recovery/dehydration process700. The NGL recovery/dehydration process 700 may dehydrate and recoversome of the NGLs from a carbon dioxide recycle stream. For example, theNGL recovery/dehydration process 700 may be implemented as part of thecarbon dioxide reinjection process 600, e.g., by separating thedehydrated carbon dioxide recycle stream 160 into an NGL rich stream 162and a purified carbon dioxide recycle stream 164.

The NGL recovery process 700 may begin by cooling the compressed carbondioxide recycle stream 158 in a heat exchanger 702. The heat exchanger702 may be any equipment suitable for heating or cooling one streamusing another stream. Generally, the heat exchanger 702 is a relativelysimple device that allows heat to be exchanged between two fluidswithout the fluids directly contacting each other. Examples of suitableheat exchangers 702 include shell and tube heat exchangers, double pipeheat exchangers, plate fin heat exchangers, bayonet heat exchangers,reboilers, condensers, evaporators, and air coolers. In the case of aircoolers, one of the fluids comprises atmospheric air, which may beforced over tubes or coils using one or more fans. In a specificembodiment, the heat exchanger 702 is a shell and tube heat exchanger.

As shown in FIG. 6, the compressed carbon dioxide recycle stream 158 maybe cooled using the cooled, purified carbon dioxide recycle stream 758.Specifically, the compressed carbon dioxide recycle stream 158 is cooledto produce the cooled carbon dioxide recycle stream 752, and the cooled,purified carbon dioxide recycle stream 758 is heated to produce thepurified carbon dioxide recycle stream 164. The efficiency of the heatexchange process depends on several factors, including the heatexchanger design, the temperature, composition, and flowrate of the hotand cold streams, and/or the amount of thermal energy lost in the heatexchange process. In embodiments, the difference in energy levelsbetween the compressed carbon dioxide recycle stream 158 and the cooledcarbon dioxide recycle stream 752 is at least about 60 percent, at leastabout 70 percent, at least about 80, or at least about 90 percent of thedifference in energy levels between the cooled, purified carbon dioxiderecycle stream 758 and the purified carbon dioxide recycle stream 164.

The cooled carbon dioxide recycle stream 752 then enters a separator718. The separator 718 may be similar to any of the separators describedherein, such as separator 102. In a specific embodiment, the separator718 is a three phase separator, which is a vessel that separates aninlet stream into three distinct phases such as a substantially vaporstream, a substantially first liquid stream (e.g., an organic liquidphase), and a substantially second liquid stream (e.g., an aqueousliquid phase). The first liquid stream may primarily comprisehydrocarbons and the second liquid stream may primarily comprise anaqueous fluid so that the first and second liquid streams are at leastpartially insoluble in each other and form two separable liquid phases.A three-phase separator may have some internal baffles and/or weirs,temperature control elements, and/or pressure control elements, butgenerally lacks any trays or other type of complex internal structurecommonly found in columns. In an embodiment, the separator 718 mayseparate the cooled carbon dioxide recycle stream 752 into a vaporrecycle stream 724, a liquid recycle stream 728, and an aqueous fluidstream 732. The aqueous fluid stream 732 exiting from the dehydrator 722may be stored, used for other processes, or discarded. The aqueous fluidstream 732 may first be treated to remove a portion of any hydrocarbonsin the stream prior to storage, further use or process, or beingdiscarded.

The vapor recycle stream 724 optionally may enter a dehydrator 720. Thedehydrator 720 may remove some or substantially all of the water fromthe vapor recycle stream 724. The dehydrator 720 may be any suitabledehydrator, such as a condenser, an absorber, or an adsorber. Specificexamples of suitable dehydrators 720 include refrigerators, molecularsieves, liquid desiccants such as glycol, solid desiccants such assilica gel or calcium chloride, and combinations thereof. The dehydrator720 also may be any combination of the aforementioned dehydrators 720and 722 arranged in series, in parallel, or combinations thereof. In aspecific embodiment, the dehydrator 720 is a glycol unit. Any wateraccumulated within or exiting from the dehydrator 720 may be stored,used for other processes, or discarded.

The dehydrator 720 may produce a dehydrated vapor recycle stream 726.The dehydrated vapor recycle stream 726 may contain little water, e.g.,liquid water or water vapor. In embodiments, the dehydrated vaporrecycle stream 726 may comprise no more than about 5 percent, no morethan about 3 percent, no more than about 1 percent, or be substantiallyfree of water.

The liquid recycle stream 728 from the separator 718 optionally mayenter a dehydrator 722. The dehydrator 722 may remove some orsubstantially all of the water from the liquid recycle stream 728. Thedehydrator 722 may be any suitable dehydrator, such as a condenser, anabsorber, or an adsorber. Suitable liquid-liquid separators such ashydro-cyclones and heater treaters also may be used. In an embodiment,the water in the liquid recycle stream 728 may be in the form ofhydrates (e.g., clathrate hydrates) and/or an emulsion. Suitableseparators utilizing physical solvents, chemical solvents, and or heatmay be used to break the hydrates and/or emulsion and separate the waterfrom the remaining liquid recycle stream 728 components. Specificexamples of suitable dehydrators 722 include hydro-cyclones, heatertreaters, molecular sieves, liquid desiccants such as glycol, soliddesiccants such as silica gel or calcium chloride, and combinationsthereof. The dehydrator 722 also may be any combination of theaforementioned dehydrators 722 arranged in series, in parallel, orcombinations thereof. Any water accumulated within or exiting from thedehydrator 722 may be stored, used for other processes, or discarded.

The dehydrator 722 may produce a dehydrated liquid recycle stream 730.The dehydrated liquid recycle stream 730 may contain little water, e.g.,liquid water or water vapor. In embodiments, the dehydrated liquidrecycle stream 730 may comprise no more than about 5 percent, no morethan about 3 percent, no more than about 1 percent, or be substantiallyfree of water.

In an embodiment, only one of the dehydrators 720, 722 may be used. Forexample, any water contained in the cooled carbon dioxide recycle stream752 may preferentially distribute to the vapor recycle stream 724 or theliquid recycle stream 728. By only using one separator 720, 722 on thestream containing the majority of the water, the dehydrationrequirements may be reduced, thereby reducing both the installation andoperating costs associated with operating the dehydration system. In anembodiment in which only one dehydrator is used, the remaining streammay pass directly from the separator 718 to the separator 706. In anembodiment, both dehydrators 720, 722 may be used, and dehydrators 720,722 may comprise different types of dehydrators. For example, dehydrator720 may comprise a gas dehydration system while dehydrator 722 maycomprise a unit designed to primarily perform a liquid-liquid phaseseparation. In an embodiment, both dehydrators 720, 722 may be used andthe separator 718 may be used to perform a first stage separation of anyfree water, thereby reducing the dehydration requirements. In stillanother embodiment, neither dehydrator 720, 722 may be used and ratherseparator 718 may be sufficient for removing any free water and therebydehydrating the cooled carbon dioxide recycle stream 752 along withperforming a first stage flash of the cooled carbon dioxide recyclestream 752 to allow the stream to be introduced to the NGL fractionator704 as separate streams. In yet another embodiment, the vapor recyclestream 724 and the liquid recycle stream 728 may be combined and passedto a single dehydrator.

The dehydrated vapor recycle stream 726 and the dehydrated liquidrecycle stream 730 then may enter an NGL fractionator 704 as separatestreams. In an embodiment, the dehydrated vapor recycle stream 726 andthe dehydrated liquid recycle stream 730 may be fed to a separator 706in the NGL fractionator 704 at separate input locations. The ability tofeed the dehydrated vapor recycle stream 726 and the dehydrated liquidrecycle stream 730 at separate locations in the separator 706 may aid inthe separation of the various components into the overhead stream 754and the bottoms stream 760. While the dehydrated vapor recycle stream726 is illustrated as entering the separator 706 above the dehydratedliquid recycle stream 730, the dehydrated vapor recycle stream 726 mayentering the separator 706 below the dehydrated liquid recycle stream730, or enter at or near the same tray and/or location. In anembodiment, the dehydrated vapor recycle stream 726 and the dehydratedliquid recycle stream 730 may be combined prior to entering the NGLfractionator 704.

The NGL fractionator 704 may comprise a separator 706, a condenser 708,and a reboiler 710. The separator 706 may be similar to any of theseparators described herein, such as separator 102. In a specificembodiment, the separator 706 is a distillation column. In anembodiment, dehydrated vapor recycle stream 726 may be introduced ontothe tray and/or inlet location (e.g., when structured packing is used)with the closest matching vapor composition in the distillation column.Similarly, the dehydrated liquid recycle stream 730 may be introducedonto the tray and/or inlet location with the closest matching liquidcomposition. Actual compositional measurements and/or process models maybe used to match the dehydrated vapor recycle stream 726 and thedehydrated liquid recycle stream 730 to the appropriate trays and/orinlet location in the distillation column.

The condenser 708 may receive an overhead stream 754 from the separator706 and produce the cooled, purified carbon dioxide recycle stream 758and a reflux stream 756, which is returned to the separator 706. Thecondenser 708 may be similar to any of the heat exchangers describedherein, such as heat exchanger 702. In a specific embodiment, thecondenser 708 is a shell and tube, kettle type condenser coupled to arefrigeration process, and contains a reflux accumulator. As such, thecondenser 708 may remove some energy 782 from the reflux stream 756 andcooled, purified carbon dioxide recycle stream 758, typically byrefrigeration. The cooled, purified carbon dioxide recycle stream 758 issubstantially similar in composition to the purified carbon dioxiderecycle stream 164 described above. Similarly, the reboiler 710 mayreceive a bottoms stream 760 from the separator 706 and produce a sourNGL rich stream 764 and a boil-up stream 762, which is returned to theseparator 706. The reboiler 710 may be like any of the heat exchangersdescribed herein, such as heat exchanger 702. In a specific embodiment,the reboiler 710 is a shell and tube heat exchanger coupled to a hot oilheater. As such, the reboiler 710 adds some energy 784 to the boil-upstream 762 and the sour NGL rich stream 764, typically by heating. Thesour NGL rich stream 764 may be substantially similar in composition tothe NGL rich stream 162, with the exception that the sour NGL richstream 764 has some additional acid gases, e.g., acid gases 770described below.

The sour NGL rich stream 764 then may be cooled in another heatexchanger 712. The heat exchanger 712 may be like any of the heatexchangers described herein, such as heat exchanger 702. For example,the heat exchanger 712 may be an air cooler as described above. Acooled, sour NGL rich stream 766 exits the heat exchanger 712 and entersa throttling valve 714. The throttling valve 714 may be an actual valvesuch as a gate valve, globe valve, angle valve, ball valve, butterflyvalve, needle valve, or any other suitable valve, or may be arestriction in the piping such as an orifice or a pipe coil, bend, orsize reduction. The throttling valve 714 may reduce the pressure,temperature, or both of the cooled, sour NGL rich stream 766 and producea low-pressure sour NGL rich stream 768. The cooled, sour NGL richstream 766 and the low-pressure sour NGL rich stream 768 havesubstantially the same composition as the sour NGL rich stream 764,albeit with lower energy levels.

The low-pressure sour NGL rich stream 768 then may be sweetened in aseparator 716. The separator 716 may be similar to any of the separatorsdescribed herein, such as separator 102. In an embodiment, the separator716 may be one or more packed columns that use a sweetening process toremove acid gases 770 from the low-pressure sour NGL rich stream 768.Suitable sweetening processes include amine solutions, physical solventssuch as SELEXOL or RECTISOL, mixed amine solution and physical solvents,potassium carbonate solutions, direct oxidation, absorption, adsorptionusing, e.g., molecular sieves, or membrane filtration. The separator 716may produce the NGL rich stream 162 described above. In addition, anyacid gases 770 accumulated within or exiting from the separator 716 maybe stored, used for other processes, or suitably disposed of. Finally,while FIGS. 5 and 6 are described in the context of carbon dioxiderecovery and/or reinjection, it will be appreciated that the conceptsdescribed herein can be applied to other recovery and/or reinjectionprocesses, for example those using nitrogen, air, or water.

As referenced above, FIG. 7 illustrates an embodiment of an NGL recoveryoptimization method 400. The NGL recovery optimization method 400 may beused to determine an improved or optimal project estimate forimplementing the NGL recovery process and recovering NGLs at a suitablerate. As such, the NGL recovery process may be configured usingappropriate equipment design based on the NGL recovery rate.Specifically, the NGL recovery optimization method 400 may design orconfigure the equipment size, quantity, or both based on an initial NGLrecovery rate and required energy, and hence estimate the projectfeasibility and cost. The method 400 may upgrade or improve the projectestimate by iteratively incrementing the initial NGL recovery rate,re-estimating the project, and comparing the two estimates.

At block 402, the method 400 may select an initial NGL recovery rate.The initial NGL recovery rate may be relatively small, such as no morethan about 20 percent recovery, no more than about 10 percent recovery,no more than about 5 percent recovery, or no more than about 1 percentrecovery. Choosing the initial NGL recovery rate at a small percentageof the total NGL amount may result in a relatively low project estimatethat may be increased gradually to reach improved estimates.

The method 400 then may proceed to block 404, where the projectequipment size may be determined based on the initial NGL recovery rate.Specifically, the size of the equipment described in the NGL recoveryprocess and any additional compressors as described above may bedetermined. In addition, the pressure and temperature ratings andmaterial compositions of such equipment may be determined at block 404,if desired.

The method 400 then may proceed to block 406, where the project may beestimated. Project estimation may comprise an economic evaluation of theNGL recovery process, and may include the cost of obtaining,fabricating, and/or field constructing the equipment sized in block 404.In addition, project estimation may include the cost of operating andmaintaining the NGL process, as well as the revenue generated by thesale or use of the products obtained by implementing the NGL process. Assuch, the project estimate may comprise the total project benefits(including production, sales, etc.) minus the total project capital andoperating costs (including cost, equipment, etc.). In some embodiments,the project estimate may be based on an existing carbon dioxidereinjection plant that lacks the NGL recovery process.

The method 400 then may proceed to block 408, where the recovery rate isincremented. The NGL recovery rate may be incremented by a relativelysmall percentage, for example no more than about 10 percent, not morethan about 5 percent, or no more than about 1 percent. The method 400then may proceed to block 410, which is substantially similar to block404. The method 400 then may proceed to block 412, which issubstantially similar to block 406.

The method 400 then may proceed to block 414, where the method 400 maydetermine whether the project estimate has improved. For instance, themethod 400 may compare the project estimate from block 412 with theprevious project estimate (either block 406 or the previous iteration ofblock 412) and determine whether the revised estimate is moreeconomically desirable. The method 400 may return to block 408 when thecondition at block 414 is met. Otherwise, the method 400 may proceed toblock 416.

At block 416, the method 400 may choose the previous project estimate asthe final estimate. For example, the method 400 may select the previousNGL recovery rate (either block 406 or the previous iteration of block412) instead of the estimate obtained at block 412. In some embodiments,the desired or optimum recovery rate selected at block 416 may representa range of desirable or optimum points, as opposed to a single point.Accordingly, the method 400 may select the equipment sizingcorresponding to the selected NGL recovery rate. The selected projectestimate and sizing then may be used for the NGL recovery process. Ofcourse, it will be appreciated that the method 400 may be revised toinclude a decremented, top-down estimation approach as opposed to anincremented, bottom-up estimation approach.

The method 400 may have several advantages over other project estimationmethods. For example, process equipment of a specific size may beselected, and the corresponding recovery rate determined. Alternatively,a required recovery rate may be selected, and the equipment sized toachieve the recovery rate. However, it has been discovered that suchapproaches are inflexible and often yields suboptimal process economics.For example, relatively high NGL recovery rates will not lead to animprovement in process economics, e.g., because of the exponentialincrease in energy consumption. In contrast, the method 400 provides aflexible approach to determining a desirable or optimal projectestimate.

In an embodiment, the equipment size may be configured to allow forvariations in recovery rates to accommodate changes in economicconditions, such as C₃₊ or energy pricing. Specifically, the equipmentdescribed herein can be sized above or below the desired or optimumamount to allow the processes described herein to operate at recoveryrates slightly greater than or slightly less than the desirable oroptimum point obtained in method 400. As the process parameters and theenergy requirements may be closely related, the ability of the processto continue to successfully operate under differing conditions may bereflected by constrained changes in the energy requirements of theprocess. When operating in the first amount 304 or the second amount 306on the curve 302 in FIG. 3, significant increases or decreases in NGLrecovery rate may be obtained with little change in the energyrequirements. Such is not the case when operating in the third amount308 on the curve 302 in FIG. 3, where significant increases or decreasesin energy requirements yield only incremental changes in NGL recoveryrate.

Example 1

In one example, a process simulation was performed using the NGLrecovery process 200 shown in FIG. 2. The simulation was performed usingthe Hyprotech Ltd. HYSYS Process v2.1.1 (Build 3198) software package.The NGL recovery process 200 separated the dehydrated carbon dioxiderecycle stream 160 into the purified carbon dioxide recycle stream 164,the NGL rich stream 162, and the acid gas stream 270. The specifiedvalues are indicated by an asterisk (*). The physical properties areprovided in degrees Fahrenheit (F), psig, million standard cubic feetper day (MMSCFD), pounds per hour (lb/hr), U.S. gallons per minute(USGPM), and British thermal units per hour (Btu/hr). The materialstreams, their compositions, and the associated energy streams producedby the simulation are provided in tables 1, 2, and 3 below,respectively.

TABLE 1 A: Material Streams Cooled, Dehydrated Cooled CO₂ Purified CO₂CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258 VaporFraction 0.9838 0.9392 1.0000 Temperature (F.) 104.0* 45.00* 4.011Pressure (psig) 340.0* 335.0 330.0 Molar Flow (MMSCFD) 17.00* 17.0015.88 Mass Flow (lb/hr)  8.049e+04  8.049e+04  7.254e+04 Liquid VolumeFlow 218.1 218.1 192.3 (USGPM) Heat Flow (Btu/hr) −2.639e+08 −2.658e+08−2.577e+08 B: Material Streams Purified CO₂ Sour NGL Cooled Sour RecycleRich Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction1.0000 0.00000 0.0000 Temperature (F.) 97.39 202.6 120.0* Pressure(psig) 325.0 340.0 635.3* Molar Flow (MMSCFD) 15.88 1.119 1.119 MassFlow (lb/hr)  7.254e+04 7947 7947 Liquid Volume Flow 192.3 25.84 25.84(USGPM) Heat Flow (Btu/hr) −2.558e+08 −8.443e+06 −8.862e+06 C: MaterialStreams Low-Pressure Sour NGL Rich Stream Acid Gas NGL Rich Name 268Stream 270 Stream 162 Vapor Fraction 0.0000 1.0000 0.0000 Temperature(F.) 120.9 100.0* 111.8 Pressure (psig) 200.3* 5.304* 185.3* Molar Flow(MMSCFD) 1.119 0.1030 1.016 Mass Flow (lb/hr) 7947 446.4 7501 LiquidVolume Flow 25.84 1.100 24.74 (USGPM) Heat Flow (Btu/hr) −8.862e+06−1.083e+06 −7.779e+06

TABLE 2 A: Stream Compositions Cooled, Dehydrated Cooled CO₂ PurifiedCO₂ CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258Comp Mole Frac (H₂S) 0.0333* 0.0333 0.0327 Comp Mole Frac (Nitrogen)0.0054* 0.0054 0.0058 Comp Mole Frac (CO₂) 0.7842* 0.7842 0.8359 CompMole Frac (Methane) 0.0521* 0.0521 0.0558 Comp Mole Frac (Ethane)0.0343* 0.0343 0.0348 Comp Mole Frac (Propane) 0.0406* 0.0406 0.0313Comp Mole Frac (i-Butane) 0.0072* 0.0072 0.0022 Comp Mole Frac(n-Butane) 0.0171* 0.0171 0.0015 Comp Mole Frac (i-Pentane) 0.0058*0.0058 0.0000 Comp Mole Frac (n-Pentane) 0.0057* 0.0057 0.0000 Comp MoleFrac (n-Hexane) 0.0070* 0.0070 0.0000 Comp Mole Frac (n-Octane) 0.0071*0.0071 0.0000 Comp Mole Frac (H₂O) 0.0000* 0.0000 0.0000 B: StreamCompositions Purified CO₂ Sour NGL Cooled Sour Recycle Rich Stream NGLRich Name Stream 164 264 Stream 266 Comp Mole Frac (H₂S) 0.0327 0.04210.0421 Comp Mole Frac (Nitrogen) 0.0058 0.0000 0.0000 Comp Mole Frac(CO₂) 0.8359 0.0500 0.0500 Comp Mole Frac (Methane) 0.0558 0.0000 0.0000Comp Mole Frac (Ethane) 0.0348 0.0281 0.0281 Comp Mole Frac (Propane)0.0313 0.1728 0.1728 Comp Mole Frac (i-Butane) 0.0022 0.0789 0.0789 CompMole Frac (n-Butane) 0.0015 0.2388 0.2388 Comp Mole Frac (i-Pentane)0.0000 0.0887 0.0887 Comp Mole Frac (n-Pentane) 0.0000 0.0866 0.0866Comp Mole Frac (n-Hexane) 0.0000 0.1063 0.1063 Comp Mole Frac (n-Octane)0.0000 0.1077 0.1077 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000 C: StreamCompositions Low-Pressure Sour NGL Acid Gas NGL Rich Rich Stream StreamStream Name 268 270 162 Comp Mole Frac (H₂S) 0.0421 0.4568 0.0000 CompMole Frac (Nitrogen) 0.0000 0.0000 0.0000 Comp Mole Frac (CO₂) 0.05000.5432 0.0000 Comp Mole Frac (Methane) 0.0000 0.0000 0.0000 Comp MoleFrac (Ethane) 0.0281 0.0000 0.0309 Comp Mole Frac (Propane) 0.17280.0000 0.1903 Comp Mole Frac (i-Butane) 0.0789 0.0000 0.0869 Comp MoleFrac (n-Butane) 0.2388 0.0000 0.2630 Comp Mole Frac (i-Pentane) 0.08870.0000 0.0977 Comp Mole Frac (n-Pentane) 0.0866 0.0000 0.0954 Comp MoleFrac (n-Hexane) 0.1063 0.0000 0.1171 Comp Mole Frac (n-Octane) 0.10770.0000 0.1186 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000

TABLE 3 Energy Streams Name Heat Flow (Btu/hr) Condenser Q Energy Stream282 1.469e+06 Reboiler Q Energy Stream 284 1.152e+06

Example 2

In another example, the process simulation was repeated using adifferent dehydrated carbon dioxide recycle stream 160. The materialstreams, their compositions, and the associated energy streams producedby the simulation are provided in tables 4, 5, and 6 below,respectively.

TABLE 4 A: Material Streams Cooled, Dehydrated Cooled CO₂ Purified CO₂CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258 VaporFraction 0.9874 0.9286 1.0000 Temperature (F.) 104.0* 60.00* 22.77Pressure (psig) 685.3* 680.3 590.0 Molar Flow (MMSCFD) 20.00* 20.0018.86 Mass Flow (lb/hr)  8.535e+04  8.535e+04  7.780e+04 Liquid VolumeFlow 258.0 258.0 232.2 (USGPM) Heat Flow (Btu/hr) −2.741e+08 −2.760e+08−2.683e+08 B: Material Streams Purified CO₂ Sour NGL Cooled Sour RecycleRich Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction1.0000 0.00000 0.0000 Temperature (F.) 87.48 290.7 120.0* Pressure(psig) 585.0 600.0 635.3* Molar Flow (MMSCFD) 18.86 1.139 1.139 MassFlow (lb/hr)  7.780e+04 7552 7552 Liquid Volume Flow 232.2 25.83 25.83(USGPM) Heat Flow (Btu/hr) −2.663e+08 −7.411e+06 −8.371e+06 C: MaterialStreams Low-Pressure Sour NGL Acid Gas NGL Rich Rich Stream StreamStream Name 268 270 162 Vapor Fraction 0.0000 1.0000 0.0000 Temperature(F.) 120.5 100.0* 118.6 Pressure (psig) 200.3* 5.304* 185.3* Molar Flow(MMSCFD) 1.139 0.02943 1.110 Mass Flow (lb/hr) 7552 141.2 7411 LiquidVolume Flow 25.83 0.3421 25.49 (USGPM) Heat Flow (Btu/hr) −8.371e+06−5.301e+05 −7.841e+06

TABLE 5 A: Stream Compositions Cooled, Dehydrated Cooled CO₂ PurifiedCO₂ CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258Comp Mole Frac (H₂S) 0.0004* 0.0004 0.0004 Comp Mole Frac (Nitrogen)0.0153* 0.0153 0.0162 Comp Mole Frac (CO₂) 0.6592* 0.6592 0.6975 CompMole Frac (Methane) 0.1813* 0.1813 0.1922 Comp Mole Frac (Ethane)0.0620* 0.0620 0.0620 Comp Mole Frac (Propane) 0.0411* 0.0411 0.0275Comp Mole Frac (i-Butane) 0.0064* 0.0064 0.0017 Comp Mole Frac(n-Butane) 0.0179* 0.0179 0.0024 Comp Mole Frac (i-Pentane) 0.0040*0.0040 0.0000 Comp Mole Frac (n-Pentane) 0.0049* 0.0049 0.0000 Comp MoleFrac (n-Hexane) 0.0030* 0.0030 0.0000 Comp Mole Frac (n-Octane) 0.0045*0.0045 0.0000 Comp Mole Frac (H₂O) 0.0000* 0.0000 0.0000 B: StreamCompositions Purified CO₂ Sour NGL Cooled Sour Recycle Rich Stream NGLRich Name Stream 164 264 Stream 266 Comp Mole Frac (H₂S) 0.0004 0.00080.0008 Comp Mole Frac (Nitrogen) 0.0162 0.0000 0.0000 Comp Mole Frac(CO₂) 0.6975 0.0250 0.0250 Comp Mole Frac (Methane) 0.1922 0.0000 0.0000Comp Mole Frac (Ethane) 0.0620 0.0613 0.0613 Comp Mole Frac (Propane)0.0275 0.2670 0.2670 Comp Mole Frac (i-Butane) 0.0017 0.0836 0.0836 CompMole Frac (n-Butane) 0.0024 0.2751 0.2751 Comp Mole Frac (i-Pentane)0.0000 0.0697 0.0697 Comp Mole Frac (n-Pentane) 0.0000 0.0858 0.0858Comp Mole Frac (n-Hexane) 0.0000 0.0527 0.0527 Comp Mole Frac (n-Octane)0.0000 0.0790 0.0790 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000 C: StreamCompositions Low-Pressure Sour NGL Acid Gas NGL Rich Rich Stream StreamStream Name 268 270 162 Comp Mole Frac (H₂S) 0.0008 0.0315 0.0000 CompMole Frac (Nitrogen) 0.0000 0.0000 0.0000 Comp Mole Frac (CO₂) 0.02500.9685 0.0000 Comp Mole Frac (Methane) 0.0000 0.0000 0.0000 Comp MoleFrac (Ethane) 0.0613 0.0000 0.0629 Comp Mole Frac (Propane) 0.26700.0000 0.2740 Comp Mole Frac (i-Butane) 0.0836 0.0000 0.0858 Comp MoleFrac (n-Butane) 0.2751 0.0000 0.2824 Comp Mole Frac (i-Pentane) 0.06970.0000 0.0716 Comp Mole Frac (n-Pentane) 0.0858 0.0000 0.0881 Comp MoleFrac (n-Hexane) 0.0527 0.0000 0.0541 Comp Mole Frac (n-Octane) 0.07900.0000 0.0811 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000

TABLE 6 Energy Streams Name Heat Flow (Btu/hr) Condenser Q Energy Stream282 1.884e+06 Reboiler Q Energy Stream 284 2.211e+06

Example 3

In a third example, the process simulation was repeated using adifferent dehydrated carbon dioxide recycle stream 160. The materialstreams, their compositions, and the associated energy streams producedby the simulation are provided in tables 7, 8, and 9 below,respectively.

TABLE 7 A: Material Streams Cooled, Dehydrated Cooled CO₂ Purified CO₂CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258 VaporFraction 1.0000 0.9988 1.0000 Temperature (F.) 104.0* 30.00* 4.617Pressure (psig) 340.0* 335.0 330.0 Molar Flow (MMSCFD) 17.00* 17.0016.82 Mass Flow (lb/hr)  8.083e+04  8.083e+04  7.968e+04 Liquid VolumeFlow 203.4 203.4 199.5 (USGPM) Heat Flow (Btu/hr) −3.016e+08 −3.032e+08−3.025e+08 B: Material Streams Purified CO₂ Sour NGL Cooled Sour RecycleRich Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction1.0000 0.00000 0.0000 Temperature (F.) 76.45 199.4 120.0* Pressure(psig) 325.0 340.0 635.3* Molar Flow (MMSCFD) 16.82 0.1763 0.1763 MassFlow (lb/hr)  7.968e+04 1153 1153 Liquid Volume Flow 199.5 3.894 3.894(USGPM) Heat Flow (Btu/hr) −3.009e+08 −1.278e+06 −1.340e+06 C: MaterialStreams Low-Pressure Sour NGL Acid Gas NGL Rich Rich Stream StreamStream Name 268 270 162 Vapor Fraction 0.0000 1.0000 0.0000 Temperature(F.) 120.4 100.0* 115.4 Pressure (psig) 200.3* 5.304* 185.3* Molar Flow(MMSCFD) 0.1763 0.01048 0.1659 Mass Flow (lb/hr) 1153 48.82 1105 LiquidVolume Flow 3.894 0.1188 3.776 (USGPM) Heat Flow (Btu/hr) −1.340e+06−1.653e+05 −1.175e+06

TABLE 8 A: Stream Compositions Cooled, Dehydrated Cooled CO₂ PurifiedCO₂ CO₂ Recycle Recycle Recycle Name Stream 160 Stream 252 Stream 258Comp Mole Frac (H₂S) 0.0031* 0.0031 0.0030 Comp Mole Frac (Nitrogen)0.0008* 0.0008 0.0008 Comp Mole Frac (CO₂) 0.9400* 0.9400 0.9493 CompMole Frac (Methane) 0.0219* 0.0219 0.0222 Comp Mole Frac (Ethane)0.0156* 0.0156 0.0157 Comp Mole Frac (Propane) 0.0116* 0.0116 0.0088Comp Mole Frac (i-Butane) 0.0015* 0.0015 0.0002 Comp Mole Frac(n-Butane) 0.0031* 0.0031 0.0001 Comp Mole Frac (i-Pentane) 0.0007*0.0007 0.0000 Comp Mole Frac (n-Pentane) 0.0006* 0.0006 0.0000 Comp MoleFrac (n-Hexane) 0.0005* 0.0005 0.0000 Comp Mole Frac (n-Octane) 0.0006*0.0006 0.0000 Comp Mole Frac (H₂O) 0.0000* 0.0000 0.0000 B: StreamCompositions Purified CO₂ Sour NGL Cooled Sour Recycle Rich Stream NGLRich Name Stream 164 264 Stream 266 Comp Mole Frac (H₂S) 0.0030 0.00940.0094 Comp Mole Frac (Nitrogen) 0.0008 0.0000 0.0000 Comp Mole Frac(CO₂) 0.9493 0.0500 0.0500 Comp Mole Frac (Methane) 0.0222 0.0000 0.0000Comp Mole Frac (Ethane) 0.0157 0.0000 0.0000 Comp Mole Frac (Propane)0.0088 0.2794 0.2794 Comp Mole Frac (i-Butane) 0.0002 0.1265 0.1265 CompMole Frac (n-Butane) 0.0001 0.2985 0.2985 Comp Mole Frac (i-Pentane)0.0000 0.0713 0.0713 Comp Mole Frac (n-Pentane) 0.0000 0.0617 0.0617Comp Mole Frac (n-Hexane) 0.0000 0.0482 0.0482 Comp Mole Frac (n-Octane)0.0000 0.0550 0.0550 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000 C: StreamCompositions Low-Pressure Sour NGL Acid Gas NGL Rich Rich Stream StreamStream Name 268 270 162 Comp Mole Frac (H₂S) 0.0094 0.1584 0.0000 CompMole Frac (Nitrogen) 0.0000 0.0000 0.0000 Comp Mole Frac (CO₂) 0.05000.8416 0.0000 Comp Mole Frac (Methane) 0.0000 0.0000 0.0000 Comp MoleFrac (Ethane) 0.0000 0.0000 0.0000 Comp Mole Frac (Propane) 0.27940.0000 0.2970 Comp Mole Frac (i-Butane) 0.1265 0.0000 0.1345 Comp MoleFrac (n-Butane) 0.2985 0.0000 0.3174 Comp Mole Frac (i-Pentane) 0.07130.0000 0.0758 Comp Mole Frac (n-Pentane) 0.0617 0.0000 0.0656 Comp MoleFrac (n-Hexane) 0.0482 0.0000 0.0512 Comp Mole Frac (n-Octane) 0.05500.0000 0.0584 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000

TABLE 9 Energy Streams Name Heat Flow (Btu/hr) Condenser Q Energy Stream282 6.236e+06 Reboiler Q Energy Stream 284 5.666e+06

Example 4

In a fourth example, a process simulation was performed using the NGLrecovery/dehydration process 700 shown in FIG. 6. The simulation wasperformed using the Bryan Research and Engineering ProMax softwarepackage. The NGL recovery/dehydration process 700 separated thecompressed carbon dioxide recycle stream 158 into the purified carbondioxide recycle stream 164, the NGL rich stream 162, and the acid gasstream 770. The specified values are indicated by an asterisk (*). Thematerial streams, their compositions, and the associated energy streamsproduced by the simulation are provided in tables 10, 11, and 12 below,respectively.

TABLE 10 A: Material Streams Compressed Cooled Carbon Purified CarbonDioxide Dioxide Carbon Dioxide Recycle Recycle Recycle Name Stream 158Stream 752 Stream 164 Temperature (° F.) 110 55 72.0898 Pressure (psig)535 532 526.909 Mole Fraction Vapor (%) 100 97.1149 100 Mole FractionLight Liquid (%) 0 2.63789 0 Mole Fraction Heavy Liquid (%) 0 0.247192 0Molecular Weight (lb/lbmol) 34.5734 34.5734 33.2372 Molar Flow(lbmol/hr) 143.165 143.165 136.153 Vapor Volumetric Flow (ft³/hr)1369.35 1144.29 1217.29 Liquid Volumetric Flow (gpm) 170.725 142.665151.766 Std Vapor Volumetric Flow (MMSCFD) 1.30389 1.30389 1.24003 StdLiquid Volumetric Flow (sgpm) 16.1721 16.1721 14.7954 Enthalpy (Btu/hr)−1.54233E+07 −1.55479E+07 −1.49692E+07 Net Ideal Gas Heating Value(Btu/ft³) 512.476 512.476 391.24 B: Material Streams Cooled, PurifiedCarbon Dioxide Dehydrated Recycle Vapor Recycle NGL Rich Name Stream 758Stream 726 Stream 162 Temperature (° F.) −4.70484 54.9077 121.117Pressure (psig) 529.909 531 438.3 Mole Fraction Vapor (%) 100 99.9993 0Mole Fraction Light Liquid (%) 0 0.000671338 100 Mole Fraction HeavyLiquid (%) 0 0 0 Molecular Weight (lb/lbmol) 33.2372 33.941 65.1996Molar Flow (lbmol/hr) 136.153 138.957 5.97957 Vapor Volumetric Flow(ft³/hr) 880.68 1140.73 10.8305 Liquid Volumetric Flow (gpm) 109.799142.221 1.35029 Std Vapor Volumetric Flow (MMSCFD) 1.24003 1.265570.0544597 Std Liquid Volumetric Flow (sgpm) 14.7954 15.4591 1.2954Enthalpy (Btu/hr) −1.50938E+07 −1.51048E+07 −405001 Net Ideal GasHeating Value (Btu/ft³) 391.24 463.982 3359.57 C: Material Streams SourNGL Cooled, Sour Aqueous Fluid Rich Stream NGL Rich Name Stream 732 764Stream 766 Temperature (° F.) 54.9077 262.193 120 Pressure (psig) 531531.909 521.909 Mole Fraction Vapor (%) 0 0 0 Mole Fraction Light Liquid(%) 100 100 100 Mole Fraction Heavy Liquid (%) 0 0 0 Molecular Weight(lb/lbmol) 18.2988 63.2785 63.2785 Molar Flow (lbmol/hr) 0.3540526.58207 6.58207 Vapor Volumetric Flow (ft³/hr) 0.103218 14.3659 11.2331Liquid Volumetric Flow (gpm) 0.0128688 1.79107 1.40049 Std VaporVolumetric Flow (MMSCFD) 0.00322458 0.0599471 0.0599471 Std LiquidVolumetric Flow (sgpm) 0.013039 1.36091 1.36091 Enthalpy (Btu/hr)−43829.7 −468892 −508612 Net Ideal Gas Heating Value (Btu/ft³) 0.4503113053.71 3053.71 D: Material Streams Low-Pressure Sour NGL Rich StreamAcid Gases Name 768 770 Temperature (° F.) 120.145 120 Pressure (psig)441.3 12.3041 Mole Fraction Vapor (%) 0 100 Mole Fraction Light Liquid(%) 100 0 Mole Fraction Heavy Liquid (%) 0 0 Molecular Weight (lb/lbmol)63.2785 42.366 Molar Flow (lbmol/hr) 6.58207 0.645859 Vapor VolumetricFlow (ft³/hr) 11.2586 147.542 Liquid Volumetric Flow (gpm) 1.4036718.3949 Std Vapor Volumetric Flow (MMSCFD) 0.0599471 0.00588224 StdLiquid Volumetric Flow (sgpm) 1.36091 0.0667719 Enthalpy (Btu/hr)−508612 −106053 Net Ideal Gas Heating Value (Btu/ft³) 3053.71 9.39946

TABLE 11 A: Stream Compositions Compressed Cooled Carbon Purified CarbonDioxide Dioxide Carbon Dioxide Recycle Recycle Recycle Name Stream 158Stream 752 Stream 164 Comp Molar Flow H₂S (lb_(mol)/hr) 0 0 0 Comp MolarFlow Nitrogen (lb_(mol)/hr) 5.42488 5.42488 5.42487 Comp Molar Flow CO₂(lb_(mol)/hr) 78.374 78.374 77.7679 Comp Molar Flow Methane(lb_(mol)/hr) 46.8833 46.8833 46.8831 Comp Molar Flow Ethane(lb_(mol)/hr) 5.04264 5.04264 4.97376 Comp Molar Flow Propane(lb_(mol)/hr) 2.60218 2.60218 1.06689 Comp Molar Flow i-Butane(lb_(mol)/hr) 0.632167 0.632167 0.0262049 Comp Molar Flow n-Butane(lb_(mol)/hr) 1.01441 1.01441 0.0106494 Comp Molar Flow i-Pentane(lb_(mol)/hr) 0.543958 0.543958 2.47836E−05  Comp Molar Flow n-Pentane(lb_(mol)/hr) 0.27933 0.27933 6.5645E−06 Comp Molar Flow n-Hexane(lb_(mol)/hr) 1.94061 1.94061 6.8325E−08 Comp Molar Flow n-Heptane(lb_(mol)/hr) 0 0 0 Comp Molar Flow H₂O (lb_(mol)/hr) 0.427428 0.4274281.88221E−05  Comp Molar Flow Diethyle Amine (lb_(mol)/hr) 0 0 0 B:Stream Compositions Cooled, Purified Carbon Dioxide Dehydrated RecycleVapor Recycle NGL Rich Name Stream 758 Stream 726 Stream 162 Comp MolarFlow H₂S (lb_(mol)/hr) 0 0 0 Comp Molar Flow Nitrogen (lb_(mol)/hr)5.42487 5.41324 5.81573E−09 Comp Molar Flow CO₂ (lb_(mol)/hr) 77.767977.1797 1.75658E−06 Comp Molar Flow Methane (lb_(mol)/hr) 46.883146.6143 2.21379E−05 Comp Molar Flow Ethane (lb_(mol)/hr) 4.97376 4.896570.068452 Comp Molar Flow Propane (lb_(mol)/hr) 1.06689 2.39516 1.53245Comp Molar Flow i-Butane (lb_(mol)/hr) 0.0262049 0.529946 0.605608 CompMolar Flow n-Butane (lb_(mol)/hr) 0.0106494 0.799268 1.00312 Comp MolarFlow i-Pentane (lb_(mol)/hr) 2.47836E−05  0.345064 0.543843 Comp MolarFlow n-Pentane (lb_(mol)/hr) 6.5645E−06 0.161123 0.279274 Comp MolarFlow n-Hexane (lb_(mol)/hr) 6.8325E−08 0.622204 1.9405 Comp Molar Flown-Heptane (lb_(mol)/hr) 0 0 0 Comp Molar Flow H₂O (lb_(mol)/hr)1.88221E−05  0.000761257 0.0062375 Comp Molar Flow Diethyle Amine(lb_(mol)/hr) 0 0 7.30571E−05 C: Stream Compositions Sour NGL Cooled,Sour Aqueous Fluid Rich Stream NGL Rich Name Stream 732 764 Stream 766Comp Molar Flow H₂S (lb_(mol)/hr) 0 0 0 Comp Molar Flow Nitrogen(lb_(mol)/hr) 7.93825E−06 5.94147E−09 5.94147E−09 Comp Molar Flow CO₂(lb_(mol)/hr) 0.00385078 0.602328 0.602328 Comp Molar Flow Methane(lb_(mol)/hr) 0.000125243 2.25954E−05 2.25954E−05 Comp Molar Flow Ethane(lb_(mol)/hr) 1.31496E−05 0.0688655 0.0688655 Comp Molar Flow Propane(lb_(mol)/hr) 6.92895E−06 1.53528 1.53528 Comp Molar Flow i-Butane(lb_(mol)/hr) 4.43906E−07 0.605962 0.605962 Comp Molar Flow n-Butane(lb_(mol)/hr) 1.35201E−06 1.00376 1.00376 Comp Molar Flow i-Pentane(lb_(mol)/hr) 3.68843E−07 0.543932 0.543932 Comp Molar Flow n-Pentane(lb_(mol)/hr) 1.57397E−07 0.279323 0.279323 Comp Molar Flow n-Hexane(lb_(mol)/hr) 1.94686E−07 1.9406 1.9406 Comp Molar Flow n-Heptane(lb_(mol)/hr) 0 0 0 Comp Molar Flow H₂O (lb_(mol)/hr) 0.3500460.00199881 0.00199881 Comp Molar Flow Diethyle Amine (lb_(mol)/hr) 0 0 0D: Stream Compositions Low-Pressure Sour NGL Rich Stream Acid Gases Name768 770 Comp Molar Flow H₂S (lb_(mol)/hr) 0 0 Comp Molar Flow Nitrogen(lb_(mol)/hr) 5.94147E−09 0 Comp Molar Flow CO₂ (lb_(mol)/hr) 0.6023280.602272 Comp Molar Flow Methane (lb_(mol)/hr) 2.25954E−05 2.56258E−07Comp Molar Flow Ethane (lb_(mol)/hr) 0.0688655 0.000254578 Comp MolarFlow Propane (lb_(mol)/hr) 1.53528 0.00159919 Comp Molar Flow i-Butane(lb_(mol)/hr) 0.605962 0.00016306 Comp Molar Flow n-Butane (lb_(mol)/hr)1.00376 0.000353691 Comp Molar Flow i-Pentane (lb_(mol)/hr) 0.5439323.41627E−05 Comp Molar Flow n-Pentane (lb_(mol)/hr) 0.279323 2.16905E−05Comp Molar Flow n-Hexane (lb_(mol)/hr) 1.9406  4.4341E−05 Comp MolarFlow n-Heptane (lb_(mol)/hr) 0 0 Comp Molar Flow H₂O (lb_(mol)/hr)0.00199881 0.0411157 Comp Molar Flow Diethyle Amine (lb_(mol)/hr) 04.17895E−20

TABLE 12 Energy Streams Name Heat Flow (Btu/hr) Condenser Energy Stream782 320524 Reboiler Energy Stream 784 253961

Example 5

In a fifth example, the process simulation was continued for the NGLupgrade process 500 shown in FIG. 4. The simulation was performed usingthe Aspen Tech. HYSYS Version 7.2 (previously Hyprotech Ltd. HYSYS)software package. The NGL upgrade process 500 separates the NGL richstream 162 into the heavy NGL stream 172 and the light NGL stream 174.In the following tables and results, the low-pressure sour NGL richstream 268 has the composition as determined by the simulation model ofthe low-pressure sour NGL rich stream 768 from Example 4. Similarly, theacid gas stream 270 has the composition as determined by the simulationmodel of the acid gas stream 770 from Example 4. In addition, the NGLrich stream 162 has the composition as determined by the simulationmodel of the NGL rich stream 162 from Example 4. The material streams,their compositions, and the associated energy streams produced by thesimulation are provided in tables 13, 14, and 15 below, respectively.

TABLE 13 A: Material Streams Low-Pressure Sour NGL Rich Stream Acid GasNGL Rich Name 268 Stream 270 Stream 162 Vapor Fraction 0.0000 1.00000.0000 Temperature (F.) 120.145 120.0 94.16 Pressure (psig) 441.312.3041 250.0 Molar Flow (MMSCFD) 0.321888 5.8822e−002 1.019 Mass Flow(lb/hr) 416.5033 27.362473 7567 Standard Liquid Volume 46.6598 2.2893840.0 Flow (barrel/day) Heat Flow (Btu/hr) −508612 −106053 −7.920e+006B: Material Streams Overhead Heavy NGL Light NGL Name Stream 524 Stream514 Stream 174 Vapor Fraction 1.0000 0.0000 0.0000 Temperature (F.)185.7 270.6 134.0 Pressure (psig) 160.0 165.0 155.0 Molar Flow (MMSCFD)0.3687 0.6507 0.3687 Mass Flow (lb/hr) 2186 5381 2186 Standard LiquidVolume 266.4 576.5 266.4 Flow (barrel/day) Heat Flow (Btu/hr)−2.029e+006 −4.885e+006 −2.367e+006 C: Material Streams Cooled, HeavyNGL Stream Name 172 Vapor Fraction 0.0000 Temperature (F.) 100.0Pressure (psig) 160.0 Molar Flow (MMSCFD) 0.6507 Mass Flow (lb/hr) 5381Standard Liquid Volume 576.5 Flow (barrel/day) Heat Flow (Btu/hr)−5.478e+006

TABLE 14 A: Stream Compositions Low-Pressure Sour NGL Acid Gas NGL RichRich Stream Stream Stream Name 268 270 162 Comp Mole Frac (H₂S) 0.0000Comp Mole Frac (Nitrogen) 0.0000 Comp Mole Frac (CO₂) 0.09151 0.932510.0000 Comp Mole Frac (Methane) 0.00000 0.00000 0.0000 Comp Mole Frac(Ethane) 0.01046 0.00039 0.0027 Comp Mole Frac (Propane) 0.23325 0.002480.1653 Comp Mole Frac (i-Butane) 0.09206 0.00025 0.0756 Comp Mole Frac(n-Butane) 0.15250 0.00055 0.2423 Comp Mole Frac (i-Pentane) 0.082640.00005 0.1092 Comp Mole Frac (n-Pentane) 0.04244 0.00003 0.0915 CompMole Frac (n-Hexane) 0.29483 0.00007 0.2943 Comp Mole Frac (n-Heptane)0.00000 0.00000 0.0191 Comp Mole Frac (n-Octane) — — 0.0000 Comp MoleFrac (H₂O) 0.00030 0.06366 0.0000 B: Stream Compositions Overhead HeavyNGL Light NGL Name Stream 524 Stream 514 Stream 174 Comp Mole Frac (H₂S)0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000 CompMole Frac (CO₂) 0.0000 0.0000 0.0000 Comp Mole Frac (Methane) 0.00000.0000 0.0000 Comp Mole Frac (Ethane) 0.0075 0.0000 0.0075 Comp MoleFrac (Propane) 0.4547 0.0013 0.4547 Comp Mole Frac (i-Butane) 0.13300.0431 0.1330 Comp Mole Frac (n-Butane) 0.2751 0.2236 0.2751 Comp MoleFrac (i-Pentane) 0.0486 0.1435 0.0486 Comp Mole Frac (n-Pentane) 0.03590.1230 0.0359 Comp Mole Frac (n-Hexane) 0.0437 0.4363 0.0437 Comp MoleFrac (n-Heptane) 0.0013 0.0292 0.0013 Comp Mole Frac (n-Octane) 0.00000.0000 0.0000 Comp Mole Frac (H₂O) 0.0000 0.0000 0.0000 C: StreamCompositions Cooled, Heavy NGL Stream Name 172 Comp Mole Frac (H₂S)0.0000 Comp Mole Frac (Nitrogen) 0.0000 Comp Mole Frac (CO₂) 0.0000 CompMole Frac (Methane) 0.0000 Comp Mole Frac (Ethane) 0.0000 Comp Mole Frac(Propane) 0.0013 Comp Mole Frac (i-Butane) 0.0431 Comp Mole Frac(n-Butane) 0.2236 Comp Mole Frac (i-Pentane) 0.1435 Comp Mole Frac(n-Pentane) 0.1230 Comp Mole Frac (n-Hexane) 0.4363 Comp Mole Frac(n-Heptane) 0.0292 Comp Mole Frac (n-Octane) 0.0000 Comp Mole Frac (H₂O)0.0000

TABLE 15 Energy Streams Name Heat Flow (Btu/hr) Reboiler Energy Stream516  25.4 × 10³ Cooling Fluid Stream 522 39.72 × 10³

It should be highlighted that in at least certain embodiments thatstreams in an NGL recovery system (e.g., a hydrocarbon feed stream, acarbon dioxide recycle stream, and/or an NGL rich stream) are notsubjected to cryogenic conditions, membranes, and/or carbon dioxiderecovery solvents between being received and being separated into outputstreams (e.g., a heavy hydrocarbon rich stream, a purified carbondioxide recycle stream, an NGL rich stream, and/or an acid gas stream).For instance, other recovery systems may use a carbon dioxide recoverysolvent to separate carbon dioxide from a stream (e.g., use a carbondioxide recovery solvent to absorb/dissolve carbon dioxide from a streamcomprising both hydrocarbons and carbon dioxide).

Furthermore, it should also be highlighted that some embodiments may usea dehydration solvent to remove water (e.g., liquid water or watervapor) despite optionally not using a carbon dioxide recovery solvent.For example, in certain circumstances, an incoming feed stream may be“wet” in that it contains some amount of water vapor. In such cases, adehydration solvent such as, but not limited to, triethylene glycol(TEG), diethylene glycol (DEG), ethylene glycol (MEG), tetraethyleneglycol (TREG), other glycols, or any other dehydration solvent may beused to remove the water from the stream. However, embodiments are notlimited to any particular method of dehydrating a stream and othermethods of dehydrating a stream can be used as well.

As used herein, the term consisting essentially of excludes additionalequilibrium-staged separation or reaction processes, but does notexclude additional piping, accumulators, heat exchangers, pipe tees andsimilar “simple” separations, valves, sensors, material transferdevices, or anything else that does not materially change the inherentproperties of a significant portion of the streams in question.

At least one embodiment is disclosed and variations, combinations,and/or modifications of the embodiment(s) and/or features of theembodiment(s) made by a person having ordinary skill in the art arewithin the scope of the disclosure. Alternative embodiments that resultfrom combining, integrating, and/or omitting features of theembodiment(s) are also within the scope of the disclosure. Wherenumerical ranges or limitations are expressly stated, such expressranges or limitations should be understood to include iterative rangesor limitations of like magnitude falling within the expressly statedranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4,etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example,whenever a numerical range with a lower limit, R_(l), and an upperlimit, R_(u), is disclosed, any number falling within the range isspecifically disclosed. In particular, the following numbers within therange are specifically disclosed: R=R_(l)+k*(R_(u)−R_(l)), wherein k isa variable ranging from 1 percent to 100 percent with a 1 percentincrement, e.g., k is 1 percent, 2 percent, 3 percent, 4 percent, 5percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent,96 percent, 97 percent, 98 percent, 99 percent, or 100 percent.Moreover, any numerical range defined by two R numbers as defined in theabove is also specifically disclosed. Use of the term “optionally” withrespect to any element of a claim means that the element is required, oralternatively, the element is not required, both alternatives beingwithin the scope of the claim. Use of broader terms such as comprises,includes, and having should be understood to provide support fornarrower terms such as consisting of, consisting essentially of, andcomprised substantially of. Accordingly, the scope of protection is notlimited by the description set out above but is defined by the claimsthat follow, that scope including all equivalents of the subject matterof the claims. Each and every claim is incorporated as furtherdisclosure into the specification and the claims are embodiment(s) ofthe present disclosure. The discussion of a reference in the disclosureis not an admission that it is prior art, especially any reference thathas a publication date after the priority date of this application. Thedisclosure of all patents, patent applications, and publications citedin the disclosure are hereby incorporated by reference, to the extentthat they provide exemplary, procedural, or other details supplementaryto the disclosure.

While several embodiments have been provided in the present disclosure,it should be understood that the disclosed systems and methods might beembodied in many other specific forms without departing from the spiritor scope of the present disclosure. The present examples are to beconsidered as illustrative and not restrictive, and the intention is notto be limited to the details given herein. For example, the variouselements or components may be combined or integrated in another systemor certain features may be omitted, or not implemented.

In addition, techniques, systems, subsystems, and methods described andillustrated in the various embodiments as discrete or separate may becombined or integrated with other systems, modules, techniques, ormethods without departing from the scope of the present disclosure.Other items shown or discussed as coupled or directly coupled orcommunicating with each other may be indirectly coupled or communicatingthrough some interface, device, or intermediate component whetherelectrically, mechanically, or otherwise. Other examples of changes,substitutions, and alterations are ascertainable by one skilled in theart and could be made without departing from the spirit and scopedisclosed herein.

What is claimed is:
 1. A method comprising: receiving a carbon dioxiderecycle stream, wherein the carbon dioxide recycle stream comprisescarbon dioxide, natural gas liquids, and acid gas; and separating thecarbon dioxide recycle stream into a purified carbon dioxide recyclestream and a natural gas liquids stream, wherein the purified carbondioxide recycle stream comprises the carbon dioxide, and wherein thenatural gas liquids stream comprises the natural gas liquids and theacid gas.
 2. The method according to claim 1, further comprisingseparating the natural gas liquids stream into a rich natural gasliquids stream and an acid gas stream, wherein the acid gas streamcomprises hydrogen sulfide and/or carbon dioxide.
 3. The methodaccording to claim 1, wherein the carbon dioxide recycle streamcomprises methane and/or ethane, and wherein the methane and/or theethane is separated from the carbon dioxide recycle stream into thepurified carbon dioxide recycle stream.
 4. The method according to claim1, further comprising separating a feed stream into the carbon dioxiderecycle stream and a heavy hydrocarbon stream, wherein the heavyhydrocarbon stream comprises C₉₊ hydrocarbons, branched hydrocarbons,and/or aromatic hydrocarbons.
 5. The method according to claim 1,wherein separating the carbon dioxide recycle stream comprises using athree phase separator to separate the carbon dioxide recycle stream intoa vapor stream, an organic liquid stream, and an aqueous liquid stream.6. The method according to claim 1, wherein receiving the carbon dioxiderecycle stream comprises receiving streams comprising natural gasliquids from a plurality of different natural gas liquid sources.
 7. Themethod according to claim 1, wherein separating the carbon dioxiderecycle stream into the purified carbon dioxide recycle stream and thenatural gas liquids stream consists essentially of: receiving the carbondioxide recycle stream at a separation column; reboiling a portion ofthe carbon dioxide recycle stream received from the separation columnwith a reboiler to generate the natural gas liquids stream; andcondensing another portion of the carbon dioxide recycle stream receivedfrom the separation column with a condenser to generate the purifiedcarbon dioxide recycle stream.
 8. A system comprising: piping configuredto receive a recycle stream, wherein the recycle stream comprises aninjection gas, natural gas liquids, and acid gas; and a separatorcoupled to the piping and configured to separate the recycle stream intoa purified recycle stream and a natural gas liquids stream, wherein thepurified recycle stream comprises the injection gas, and wherein thenatural gas liquids stream comprises the natural gas liquids and theacid gas.
 9. The system according to claim 8, wherein the system isfurther configured to separate the natural gas liquids stream into asweetened natural gas liquids stream and an acid gas stream, wherein theacid gas stream comprises carbon dioxide and/or hydrogen sulfide. 10.The system according to claim 8, wherein the system is furtherconfigured to dehydrate the recycle stream and cool the recycle streamusing the purified recycle stream.
 11. The system according to claim 8,wherein the separator comprises a three phase separator that isconfigured to separate the recycle stream into a vapor stream, anorganic liquid stream, and an aqueous liquid stream.
 12. The systemaccording to claim 8, wherein the piping is configured to receivestreams comprising natural gas liquids from a plurality of differentnatural gas liquid sources.
 13. The system according to claim 8, whereinthe separator consists essentially of a separation column, a reboiler,and a condenser, wherein the separation column receives the recyclestream, wherein the reboiler receives a first portion of the recyclestream from the separation column and generates the natural gas liquidsstream, and wherein the condenser receives a second portion of therecycle stream from the separation column and generates the purifiedrecycle stream.
 14. A set of process equipment comprising: an input lineconfigured to receive a recycle stream, wherein the recycle streamcomprises an injection gas, natural gas liquids, and acid gas; aseparator configured to receive the recycle stream from the input lineand separate the recycle stream into a purified recycle stream and anatural gas liquids stream; a first output line configured to output thepurified recycle stream from the separator, wherein the purified recyclestream comprises the injection gas; and a second output line configuredto output the natural gas liquids stream from the separator, wherein thenatural gas liquids stream comprises the natural gas liquids and theacid gas.
 15. The set of process equipment according to claim 14,wherein the separator comprises a three phase separator that isconfigured to separate the recycle stream into a vapor stream, anorganic liquid stream, and an aqueous liquid stream.
 16. The set ofprocess equipment according to claim 14, wherein the input line isconfigured to receive streams comprising natural gas liquids from aplurality of different natural gas liquid sources.
 17. The set ofprocess equipment according to claim 14, further comprising an injectiongas makeup line configured to add additional injection gas to thepurified recycle stream, wherein the additional injection gas comprisescarbon dioxide, nitrogen, methane, ethane, air, and/or water.
 18. Theset of process equipment according to claim 14, further comprising: asecond separator that is configured to separate heavy hydrocarbons fromthe recycle stream; and a third separator that is configured to separatethe acid gas from the natural gas liquids.
 19. The set of processequipment according to claim 14, further comprising one or morecompressors configured to increase a pressure of the recycle streambefore entering the separator and increase a pressure of the purifiedrecycle stream after leaving the separator.
 20. The set of processequipment according to claim 14, wherein the separator consistsessentially of a separation column, a reboiler, and a condenser, whereinthe separation column receives the recycle stream, wherein the reboilerreceives a first portion of the recycle stream from the separationcolumn and generates the natural gas liquids stream, and wherein thecondenser receives a second portion of the recycle stream from theseparation column and generates the purified recycle stream.